Oil and natural gas are often found together in the same reservoir. The composition of the raw natural gas extracted from producing wells depends on the type, depth, and location of the underground deposit and the geology of the area. During production, oil, gas, and water flow to the surface, passing as an emulsion or a mixture.
During a well's flowing life, liquids tend to migrate down the tubing and start to collect at a well bottom, causing a gradual increase in back pressure. Fluid buildup may cause the lifting efficiency of a well to decrease and in some cases, may even cause a well to cease to flow.
Operators may use any number of artificial lift techniques to raise fluid to the surface after a well slows or ceases to flow. One known method comprises plunger lift. The function of the plunger is to prevent fluid buildup from accumulating to the point that the well would cease to flow. In addition, a plunger can minimize a lengthy “shut in” time during which a well is enabled to recover.
The operation of a plunger lift system relies on the natural buildup of pressure in a well during the time that the well is shut in at the surface by a wellhead controller (or in an “off” mode). When a well is shut in, casing pressure is allowed to build up. In a shut in mode, no production occurs. When the casing pressure has sufficiently built up to enable the accumulated liquids in the tubing to be lifted along with the plunger, the well is opened up. A plunger lift system operates to “lift” oil or water and natural gas from a well bottom during natural gas production when the well is in an “on” mode, thus unloading fluid buildup and increasing the productivity of oil and natural gas wells. Functionally, the plunger provides a mechanical interface between the produced liquids and the gas. This mechanical interface eliminates liquid fallback which thereby boosts a well's lifting efficiency.
In the industry, the optimization of plunger lift has primarily focused on changing the on/off cycle time based on factors such as time, differential pressure, plunger arrival speeds, etc. In fact, most plunger lift controllers commonly pre-set a minimum off time or fall time on the premise that this minimum time will allow the plunger to fall safely to the bottom of the well before the on time cycle is enabled. With the disclosed method, fall time can be optimized to provide more effective well control functions.
It is well-known in the industry that the science of determining fall time can be imprecise. In general, operators often determine that the plunger is on bottom based on an arbitrary interval of time, a guess. For example, an operator can assume it takes a plunger 45 minutes to travel to well bottom. This travel time is typically referred to as “fall time,” which can be the actual or estimated interval of time when a motor valve is shut to close the flowline and when the plunger hits bottom. Many factors, however, can affect the actual fall time of a plunger. Different types and brands of plungers fall at different rates. For example, a 2⅜″ pad-type plunger can have a fall time of about 48 minutes. In the same well, a bar-stock plunger can fall in about 22 minutes; a by-pass plunger can reach bottom in about seven minutes. In addition, new plungers have been observed to fall at different rates than worn plungers. Therefore, a worn bar-stock plunger can take considerably less time reaching bottom than a new bar-stock plunger with a fall time of 22 minutes.
Fall time can also be a function of a well's depth and the amount and composition of liquid in the well. Well maturity can also alter plunger fall times. As a well matures, it can produce more or less fluid or gas through which a plunger falls. In addition, the presence of salt, sand, or solids can have an influence on how quickly the plunger reaches bottom. Well bore features can also affect fall time. Such features can include but are not limited to the condition of the tubing, whether the tubing is rough or smooth, the type of rod-cuts, the existence of tight spots, scale, and/or paraffin build up. Other conditions affecting plunger fall time would be known to those skilled in the art.
U.S. Pat. No. 6,634,426 to McCoy et al. teaches the tracking of plunger position by monitoring acoustic signals generated by an echometer as the plunger falls down the tubing. Plunger arrival on the bottom is shown in FIG. 12, for example. Plunger arrival on the bottom is also charted using data from tubing pressure and casing pressure signals. See also FIG. 12. McCoy et al., however, do not provide an operator and/or a well controller with the ability to manually and/or automatically adjust a plunger's fall time.
To maximize a plunger's function, the well should be opened up when the plunger is on well bottom. In some cases, the plunger may not actually be located on bottom when a flowline is opened. Here, the well operator may not discover that the plunger did not lift its load potential because some fluid is actually seen at the surface. The fluid carried may only reflect a portion of the liquid load potential. The act of leaving liquid downhole is inefficient because the well will remain “loaded up” and will only flow for a short time before it will need to be shut in to recover. In other cases, the plunger may be on bottom for a longer period of time than necessary. In the example above where an operator estimates a fall time of 45 minutes, a plunger could actually be on bottom in 25 minutes, causing a well to be potentially shut in for 20 minutes longer than necessary. Using the correct fall time, the well could be flowing 20 minutes longer per cycle. For example, with 20 cycles per day, an additional 20 minutes of flow time would result in about 400 minutes of flow time per well that was not being realized. In a field having multiple plunger lift wells, the potential sales realized could be significant. Therefore, it can be a useful objective for an operator and/or well controller to use various well parameters, including that of a pressure signature or slope change, to help indicate when a plunger is on bottom to optimize the time when the well may be opened up.
Typically, pressure transducers mounted to the casing and the tubing can provide data that correlate with pressure differentials that can signal a controller when a well is ready to turn on or turn off. In the industry, however, pressure data has not been used to track plunger fall time for well optimization. To detect a slope change, which indicates that a plunger has reached fluid or bottom, frequent samples may provide an accurate picture of what can be occurring downhole. For example, a device could sample as often as every second or faster to obtain downhole travel data. It is unlikely that common well controller systems that sample as often as every 4-30 minutes, can detect the details of a pressure signature or slope change. The disclosed system provides a well controller that can see and interpret pressure signature and/or slope change and allow manual and or automatic adjustments to plunger fall time.